US8336642B2 - Drilling system - Google Patents

Drilling system Download PDF

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Publication number
US8336642B2
US8336642B2 US11/997,416 US99741606A US8336642B2 US 8336642 B2 US8336642 B2 US 8336642B2 US 99741606 A US99741606 A US 99741606A US 8336642 B2 US8336642 B2 US 8336642B2
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Prior art keywords
drilling
drill bit
bit
control
drive mechanism
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Expired - Fee Related, expires
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US11/997,416
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US20090008150A1 (en
Inventor
Eric Lavrut
Pierre-Jérôme Acquaviva
Henri Denoix
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: ACQUAVIVA, PIERRE-JEROME, DENOIX, HENRI, LAVRUT, ERIC
Publication of US20090008150A1 publication Critical patent/US20090008150A1/en
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E21B44/02—Automatic control of the tool feed
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/18—Anchoring or feeding in the borehole

Definitions

  • This invention relates to a drilling system and method that is particularly applicable to drilling with flexible conveyance systems such as wireline and coiled tubing.
  • CTO Coiled tubing drilling
  • CTD has remained a niche application, with primary markets limited to thru-tubing re-entries wells, under balanced and slim hole drilling. This limited expansion is due to certain inherent disadvantages of CTD:
  • This invention aims to address some or all of the problems encountered with the prior art systems.
  • One aspect of the invention comprises a drilling system for drilling a borehole in an underground formation, comprising a rotary drill bit, a drilling drive mechanism that is capable of applying both rotating the drill bit and applying an axial force to the drill bit, and a control system that is capable of controlling the drive mechanism so as to control rotation of the drill bit and the axial force applied to the drill bit in order to control the depth of cut created by the drill bit when drilling through the formation.
  • Another aspect of the invention comprises a method of drilling a borehole in an underground formation with a rotary drill bit, comprising applying rotation and an axial force to the drill bit and controlling the rotation and axial force so as to control the depth of cut created by the drill bit when drilling through the formation.
  • This invention differs from previously proposed techniques in that depth-of-cut (DOC) is used as a controlling/controlled parameter rather than a mere product of the drilling action as in other techniques.
  • DOC depth-of-cut
  • a flexible conveyance system such as a wireline or coiled tubing, can be provided, extending from the drilling drive mechanism along the borehole to the surface.
  • the drilling drive mechanism can comprise an anchoring mechanism, operable to anchor the drive system in the borehole to provide a reaction to the rotation and axial force applied to the drill bit.
  • the drilling drive mechanism can comprise a rotary drive portion, the control system being capable of controlling the torque applied to the bit and the rate of rotation of the bit in order to control the depth of cut; and an axially-extendable drive portion, the control system being able to measure and control extension of the axially-extendable drive portion in order to control the depth of cut.
  • Electric or hydraulic motors can be used in the drilling drive mechanism
  • the means of providing electric power can include a cable, in the case of coiled tubing as the conveyance system, running inside the coiled tubing, a cable clamped to the coiled tubing at regular intervals, or the use of the wires of an electric coiled tubing
  • downhole drilling system is hydraulically powered and it can use a downhole alternator to convert hydraulic energy to electric energy needed by the tools.
  • the drilling drive mechanism and the control system are preferably included in a downhole unit that can be connected to the conveyance system.
  • the downhole unit can be moved through the borehole using the flexible conveyance system which is then isolated from torque and axial force generated when drilling through the formation, by the use of the anchoring mechanism described above, for example.
  • FIG. 1 shows a drilling system according to an embodiment of the invention
  • FIG. 2 is a plot of Rate of Penetration vs rock hardness
  • FIG. 3 is a diagram of the control system used in the drilling system of FIG. 1 .
  • the invention is based on control of the drilling process by controlling the penetration per bit revolution (Depth of Cut control). Because the depth of cut reflects the size of the cuttings produced, such control can be used to create relatively small cuttings at all times (smaller than in conventional drilling), whose transport over a long distance requires much less power.
  • the actual drilling operation is performed by applying controlled weight to the drill bit (WOB) that is rotated from surface or with a drilling motor to provide RPM to the bit, resulting in penetration into the formation (ROP).
  • WOB drill bit
  • ROP drilling motor
  • the torque and RPM encountered at the drill bit (TOB) is a product of the resistance of the formation and the torsional stiffness of the drill string to the rotary drilling action of the drill bit.
  • WOB and RPM are products of this control.
  • the drilling system according to the invention does not take the same approach. It is possible to control the length drilled per bit revolution (also called “depth of cut” or DOC), for example by measuring, at each instant, the penetration into the formation (ROP) and the bit rotation speed (RPM).
  • the weight on bit (WOB) in this case is only the reaction of the formation to the drilling process.
  • FIG. 1 A drilling system according to an embodiment of the invention for drilling boreholes in underground formations is shown in FIG. 1 .
  • the system includes a downhole drilling unit comprising a rotary drive system 10 carrying a drill bit 12 .
  • An axial drive system 14 is positioned behind the rotary drive system 10 and connected to the surface a control section 16 and coiled tubing 18 carrying an electric cable (not shown).
  • the rotary drive system 10 includes an electric motor but which the drill bit 12 is rotated.
  • the power of the motor will depend on its size although for most applications, it is likely to be no more than 3 kW.
  • the drilling system is run into the borehole 20 until the bit 12 is at the bottom. Drilling proceeds by rotation of the bit 12 using the rotary drive system 10 and advancing the bit into the formation by use of the axial drive system 16 . Control of both is effected by the control system 16 which can in turn be controlled from the surface or can run effectively independently.
  • the size of the coiled tubing 18 used can be smaller than with previous CTD systems. Because the coiled tubing is not required to generate weight on bit, the basic functions to be performed by the coiled tubing string are limited to:
  • the drilling system generates all drilling effort downhole and therefore eliminates the need to transfer drilling forces, such as weight-on-bit, from surface via the coiled tubing to the bit 12 .
  • the system also controls the drilling process so as to generate small drill cuttings which reduces the hydraulics requirements for cuttings transport back to the surface.
  • the axial drive system is preferably a push-pull tractor system such as is described in PCT/EP04/01167.
  • the tractor 14 has a number of features that allow it to operate in a drilling environment, including:
  • Certain features can be optimised for efficient tripping, such as a fast tractoring speed (speed of moving the downhole unit through the well), and the capabilities of crawling inside casing or tubing.
  • a fast tractoring speed speed of moving the downhole unit through the well
  • crawling inside casing or tubing In order for the tractor to be useful for re-entry drilling, it needs the ability to cross a window in the casing and to be compatible with a whipstock.
  • the tractor uses the push-pull principle. This allows dissociation of coiled tubing pulling and drilling, which helps accurate control of the weight on bit.
  • a suitable form of tractor is described in European patent application no. 04292251.8 and PCT/EP04/01167.
  • the tractor is a continuous system, with wheels or chains or any other driving mechanism.
  • tractor 14 also allows a shorter build-up radius and a longer lateral when compared to conventional CTO in which the coiled tubing is under tension when drilling with a tractor; thus avoiding buckling problems and giving essentially no limit on the length of the horizontal or deviated well.
  • the drilling unit is electrically powered. Drilling RPM (and torque) is generated through conversion of electric energy. Therefore, the drilling unit does not rely on the flow of drilling fluid through the coiled tubing to a drilling motor to generate RPM (as is the case in conventional drilling techniques). Hence, the coiled tubing hydraulics are only needed to transport the cuttings.
  • the motor 10 is provided with power by means of an electric cable which also provides a medium for a two-way high-speed telemetry between surface and downhole systems, thus enabling a better control of downhole parameters.
  • Intelligent monitoring of downhole parameters can help avoid or minimize conventional drilling problems such as stick-slip motion, bit balling, bit whirling, bit bouncing, etc.
  • An electric cable can be deployed along with the coiled tubing. This can be achieved in various configurations, including:
  • the downhole drilling assembly can be hydraulically powered.
  • the downhole drilling system can be hydraulically powered and equipped with a downhole alternator to provide electric power to tool components. In this configuration, there is no need for electric lines from the surface.
  • the control system 16 provides power and control the axial and rotary drive systems 10 , 14 . It comprises sensors to measure key drilling parameters (such as instantaneous penetration rate, torque on bit, bit RPM, etc.) and can be split in several modules.
  • key drilling parameters such as instantaneous penetration rate, torque on bit, bit RPM, etc.
  • FIG. 2 shows a plot of ROP vs rock hardness (hard at the left, soft at the right).
  • Line A shows the increase in ROP as rock becomes softer assuming a maximum drilling power of 3 kW.
  • the greater the ROP the greater the size of cuttings. Therefore, by controlling the ROP, the size of cuttings can be controlled. Imposing a size limit to the cuttings produced, for example 200 ⁇ m (Line B) means that above a certain power, ROP must be reduced if the cuttings size is not to exceed the limit. This could be achieved by direct control of ROP which is possible with a tractortype axial drive, and/or by controlling the power to limit the ROP.
  • controlling the RPM may be a particularly convenient way to control power at the bit.
  • Other drilling parameters can also be optimised to achieve the required cutting size limit, by the physical setup of the drilling system or by operational control.
  • the system is controlled to optimize ROP at all time while still staying within the cuttings size limit imposed (Line C).
  • the drilling system can include an anchoring mechanism 22 , operable to anchor the drilling system in the borehole.
  • the anchoring mechanism 22 is shown in FIG. 1 to be affixed to the rotary drive system 10 . It should be understood that the anchoring mechanism 22 can also be affixed to other suitable locations, e.g., the axial drive system 14 .
  • the control software is configured to control the drilling process to generate small cuttings. Such control can be performed in several ways including, for example, from a surface unit, in real time, through use of a telemetry system.
  • the system can be autonomous (especially when there are no electric lines to surface).
  • the downhole drilling system can include embedded software to control the progress of drilling operations.
  • the downhole drilling system can be configured to accept hydraulic commands from surface (downlink).
  • FIG. 3 shows the functional structure of one embodiment of a control system.
  • the drilling system shown in Figure has various drilling parameters that are measured during operation. These include TOB. ROP, RPM and WOB. There are also controlled parameters including DOG (also considered as cuttings size and/or ROP, maximum set by user depending on cuttings transport environment, drilling fluid type, etc.), power (set by user depending on temperature environment rock type, hardware limitations, etc.) and RPM (set by user dependent on environment, vibrations, etch).
  • DOG also considered as cuttings size and/or ROP, maximum set by user depending on cuttings transport environment, drilling fluid type, etc.
  • power set by user depending on temperature environment rock type, hardware limitations, etc.
  • RPM set by user dependent on environment, vibrations, etch
  • the operator sets max DOC, max power and RPM and drilling commences.
  • measurements are made of the drilling parameters listed above.
  • a first calculated value ROP1 is obtained from the measured RPM and the set DOC.
  • a second calculated values ROP2 is obtained from the measured RPM, TOB and the set max power. The lower of ROP1 and ROP2 is selected and PID processed with regard to the measured ROP to provide a command signal ROP C that is used to control ROP of the drilling system.
  • the measured and set RPM are PID processed to provide a command signal RPM C that is used to control the RPM of the system.
  • WOB is measured but not used in any of the control processes or actively controlled.
  • WOB is a product of the drilling process rather than one of the main controlling parameters.
  • An example of a typical conventional CTD job might comprise use of a 23 ⁇ 8-in coiled tubing to drill a 33 ⁇ 4-in (95 mm) lateral hole.
  • a system according to the invention can allow a similar hole to be drilled with a coiled tubing less than 11 ⁇ 2 in, while ensuring essentially the same functions as is discussed below.
  • a typical conventional CTD job requires about 80-gpm (360 litres per minute) of mud flow to ensure proper cuttings transport.
  • this drilling fluid flow rate corresponds to a drilling fluid velocity of 1.2-m/s in the wellbore annulus, which is considered to be a general criterion for efficient transport of drill cuttings in conventional drilling.
  • the drilling fluid mean velocity is only 0.5-m/s in the well annulus, but this will be sufficient for effective transport of the small cuttings generated.
  • the mechanical properties (load capacity and torsional strength) of the small coiled tubing are lower than in conventional CTD but this is not a limitation since the tractor handles most mechanical forces (torque and weight on bit).
  • the weight of the drum is 2.6 times lower with the using the smaller coiled tubing available in the present invention.
US11/997,416 2005-08-08 2006-07-14 Drilling system Expired - Fee Related US8336642B2 (en)

Applications Claiming Priority (5)

Application Number Priority Date Filing Date Title
EP05291698 2005-08-08
EP05291698A EP1780372B1 (fr) 2005-08-08 2005-08-08 Système de forage
EPEP05291698.8 2005-08-08
PCT/EP2006/006955 WO2007017046A1 (fr) 2005-08-08 2006-07-14 Systeme de forage
EPPCT/EP2006/006955 2006-07-14

Publications (2)

Publication Number Publication Date
US20090008150A1 US20090008150A1 (en) 2009-01-08
US8336642B2 true US8336642B2 (en) 2012-12-25

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US11/997,416 Expired - Fee Related US8336642B2 (en) 2005-08-08 2006-07-14 Drilling system

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US (1) US8336642B2 (fr)
EP (1) EP1780372B1 (fr)
AT (1) ATE452277T1 (fr)
CA (1) CA2618236C (fr)
DE (1) DE602005018367D1 (fr)
RU (1) RU2008108986A (fr)
WO (1) WO2007017046A1 (fr)

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US20110083900A1 (en) * 2007-11-23 2011-04-14 Eric Lavrut Downhole drilling system

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US8245796B2 (en) * 2000-12-01 2012-08-21 Wwt International, Inc. Tractor with improved valve system
WO2005090739A1 (fr) * 2004-03-17 2005-09-29 Western Well Tool, Inc. Pince a genouillere pour chaines a rouleaux pour tracteur de fond de puits
DE602005018367D1 (de) * 2005-08-08 2010-01-28 Schlumberger Technology Bv Bohrsystem
US7624808B2 (en) 2006-03-13 2009-12-01 Western Well Tool, Inc. Expandable ramp gripper
US7748476B2 (en) * 2006-11-14 2010-07-06 Wwt International, Inc. Variable linkage assisted gripper
EP2140099B1 (fr) * 2007-04-24 2011-09-14 Welltec A/S Outil d'ancrage
GB2454702A (en) * 2007-11-15 2009-05-20 Schlumberger Holdings Cutting removal with a wireline lateral drilling tool
GB2454701B (en) * 2007-11-15 2012-02-29 Schlumberger Holdings Methods of drilling with a downhole drilling machine
GB2454895B (en) * 2007-11-22 2012-01-11 Schlumberger Holdings Flow diverter for drilling
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US20110036637A1 (en) * 2009-08-11 2011-02-17 Robert Cousineau Seismic tool assembly for use in anchor insertion
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US9447648B2 (en) 2011-10-28 2016-09-20 Wwt North America Holdings, Inc High expansion or dual link gripper
MX355314B (es) 2011-11-04 2018-04-16 Schlumberger Technology Bv Método y sistema para una operación de trituración automática.
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US9488020B2 (en) 2014-01-27 2016-11-08 Wwt North America Holdings, Inc. Eccentric linkage gripper
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Also Published As

Publication number Publication date
CA2618236A1 (fr) 2007-02-15
US20090008150A1 (en) 2009-01-08
CA2618236C (fr) 2014-11-04
DE602005018367D1 (de) 2010-01-28
EP1780372B1 (fr) 2009-12-16
RU2008108986A (ru) 2009-09-20
WO2007017046A1 (fr) 2007-02-15
ATE452277T1 (de) 2010-01-15
EP1780372A1 (fr) 2007-05-02

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